Carbon dioxide-based geothermal energy generation systems and methods related thereto

ABSTRACT

Novel carbon dioxide-based geothermal energy generation systems, i.e., carbon plume geothermal (CPG) systems, and methods are provided. With the novel systems and methods described herein, geothermal energy can now be provided at lower temperatures and at locations other than hot, dry rock formations, without negatively impacting the surrounding area through use of large-scale hydrofracturing. Use of a carbon dioxide-based geothermal system further provides a means for sequestering and storing excess carbon dioxide, rather than having it released to the atmosphere.

This application is a continuation of U.S. application Ser. No.13/202,746, filed Sep. 16, 2011, which is a National Stage Applicationunder 35 U.S.C. §371 of PCT/US2010/000756, filed Mar. 12, 2010 andpublished as WO 2010/104599 on Sep. 16, 2010, which application claimsthe benefit under 35 U.S.C. 119 (e) of U.S. Provisional Application Ser.No. 61/159,948 filed on Mar. 13, 2009, all of which are herebyincorporated by reference in their entirety.

BACKGROUND

In light of global climate change and in response to an increased desireto reduce dependence on foreign oil supplies, renewable energy systems,such as wind, solar and geothermal-based systems are being increasinglyresearched and developed. However, many such systems have only limitedpotential due to, for example, high costs, overall processinefficiencies, possible adverse environmental impact, and the like.

What is needed, therefore, are cost effective renewable energy systemswhich are not only efficient, but can improve the environment.

SUMMARY

The inventors recognize the need for providing a cost effective carbondioxide based geothermal energy system which, in some embodiments,provides added benefits for the environment by sequestering andcontaining excess carbon dioxide. In one embodiment, a system comprisingone or more injection wells for accessing one or more reservoirs havinga first temperature, wherein the one or more reservoirs are locatedbelow one or more caprocks and are accessible without using large-scalehydrofracturing, each of the one or more injection wells having aninjection well reservoir opening; one or more production wells, eachhaving a production well reservoir opening, wherein a non-water basedworking fluid can be provided to the one or more injection wells at asecond temperature lower than the first temperature and exposure of thenon-water based working fluid to the first temperature can produceheated non-water based working fluid capable of entering each of the oneor more production well reservoir openings; and an energy convertingapparatus connected to each of the one or more injection wells and theone or more productions wells, wherein thermal energy contained in theheated non-water based working fluid can be converted to electricity,heat, or combinations thereof, in the energy converting apparatus isprovided.

In various embodiments, each of the one or more injection wells and eachof the one or more production wells are located in the same channel andthe system further comprises one or more injection pipes and one or moreproduction pipes connected to the channel.

In various embodiments, the system further comprises a non-water basedworking fluid source, such as carbon dioxide (e.g., supercritical carbondioxide) obtainable from a power plant (e.g., ethanol plant orfossil-fuel based power plant) or an industrial plant. In oneembodiment, the energy converting apparatus comprises one or moreexpansion devices and one or more generators, one or more heatexchangers or a combination thereof. In one embodiment, the one or moregenerators can provide electricity to an electricity provider and thesystem further comprises the electricity provider. Additionally, in oneembodiment, each of the one or more heat exchangers can provide heat toa heat provider and the system further comprises the heat provider, suchas a direct use provider or a ground heat pump.

In one embodiment, the system further comprises one or more coolingunits fluidly connected to the one or more production wells and the oneor more injection wells.

In one embodiment, a method comprising accessing one or more undergroundreservoirs having a natural temperature, the one or more reservoirslocated beneath one or more caprocks; introducing a non-water basedworking fluid (e.g., carbon dioxide, such as supercritical carbondioxide) into the one or more reservoirs; exposing the non-water basedfluid to the natural temperature to produce heated fluid; and extractingthermal energy from the fluid, without using large-scalehydrofracturing, is provided.

In various embodiments, the heated fluid also contains native fluidpresent in the one or more reservoirs. In one embodiment, the one ormore caprocks each have a permeability ranging from about 10⁻¹⁶ m² toabout 0 m² and the one or more reservoirs each have a porosity rangingfrom about one (1) % to about 50% and a permeability ranging from about10⁻¹⁶ m² to about 10⁻⁶ m², with each of the one or more reservoirshaving a natural temperature between about −30° C. and about 300° C.

In one embodiment, the thermal energy is used to produce electricity, toheat a working fluid in one or more heat exchangers, to providecondensed fluid to the one or more reservoirs, to provide cooled fluidto the one or more reservoirs, to provide shaft power to one or morepumps or compressors, or a combination thereof. In various embodiments,the electricity is produced either by providing the hot fluid to one ormore expansion devices or by providing the working fluid heated in theone or more heat exchangers to the one or more expansion devices,wherein the one or more expansion devices produces shaft power to one ormore generators, which, in turn, produce the electricity.

In one embodiment, the working fluid heated in the one or more heatexchangers provides heat for direct use, for groundwater heat pumps, fora Rankine power cycle, or a combination thereof. In various embodiments,the method further comprises choosing the underground reservoir;transporting a non-water based working fluid source to an area proximateto the injection well; converting the non-water based working fluidsource into a non-water based working fluid; and providing the heatenergy to a customer.

The geothermal energy obtained using the novel systems and methodsdescribed herein can be used for a variety of applications, including,but not limited to, electricity generation and/or direct uses (e.g.,aquaculture, greenhouse, industrial and agricultural processes, resorts,space and district heating (wells to structures) and/or ground-sourceheat pumps. Furthermore, cascading systems can be used to draw offenergy at decreasing temperatures, thus allowing a single geothermalresource to be used for multiple purposes.

The ability to also geologically sequester carbon dioxide from varioussources and use it to generate energy and, optionally, store excesscarbon dioxide, means that the novel systems and methods describedherein can also serve as a means to mitigate global warming.Additionally, the novel embodiments described herein can increasecarbon-sequestration-based revenue potential from carbon offset sales incarbon cap and trade and similar markets.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a simplified schematic diagram of an energy generation systemaccording to an embodiment of the invention.

FIG. 2 is a simplified schematic diagram of an alternative energygeneration system according to an embodiment of the invention.

FIG. 3 is a simplified schematic diagram of another alternative energygeneration system according to an embodiment of the invention.

FIG. 4 is a simplified schematic diagram of yet another alternativeenergy generation system according to an embodiment of the invention.

FIG. 5 is a cross-section of Minnesota's Rift System (MRS).

FIG. 6 is an enlarged view of a portion of FIG. 5 taken from within box6-6 according to an embodiment of the invention.

FIG. 7 is an illustration of a geological structure used for a numericalmodel of a power generation system according to an embodiment of theinvention.

FIG. 8 is a geological model showing dimensions and solute concentrationaccording to an embodiment of the invention.

FIG. 9 is an illustration of an exemplary geometrical configurationaccording to an embodiment of the invention.

FIG. 10 is a graph showing temperature versus distance from an injectionwell to a production well for a porous medium in a carbon dioxide (CO₂)plume geothermal (CPG) system and various fracture spacings in anenhanced geothermal system (EGS) system according to an embodiment ofthe invention.

FIG. 11 is a graph showing heat extraction rate versus time for a porousmedium in a CPG system and various fracture spacings in an EGS systemaccording to an embodiment of the invention.

FIG. 12 is a graph showing heat extraction rate versus time for a CPGsystem as compared to a water system according to an embodiment of theinvention.

FIG. 13 is a graph showing density versus distance from injection wellto production well for a CPG system as compared to a water systemaccording to embodiments of the invention.

FIG. 14 is a graph showing Rayleigh number versus distance frominjection well to production well for a CPG system as compared to awater system according to an embodiment of the invention.

FIG. 15 is a graph showing Prandtl number versus distance from injectionwell to production well for a CPG system as compared to a water systemaccording to an embodiment of the invention.

DETAILED DESCRIPTION

In the following detailed description, reference is made to theaccompanying drawings that form a part hereof, and in which is shown byway of illustration, specific embodiments in which the invention may bepracticed. These embodiments are described in sufficient detail toenable those skilled in the art to practice the invention, and it is tobe understood that other embodiments may be utilized. It is also to beunderstood that structural, procedural, chemical and system changes maybe made without departing from the spirit and scope of the presentinvention. The following detailed description is, therefore, not to betaken in a limiting sense, and the scope of the present invention isdefined by the appended claims and their equivalents.

The detailed description begins with a definition section followed by abrief overview of conventional geothermal energy technology, adescription of the embodiments, an example section and a briefconclusion.

In one embodiment, novel carbon dioxide-based geothermal energygeneration systems, i.e., carbon plume geothermal (CPG) systems, andmethods are provided. With the novel systems and methods describedherein, geothermal energy can now be provided at lower reservoirtemperatures and at locations other than hot, dry rock formations,without negatively impacting the surrounding area through use oflarge-scale hydrofracturing. Use of a carbon dioxide-based geothermalsystem further provides a means for sequestering and storing excesscarbon dioxide, rather than having it released to the atmosphere.

Conventional Geothermal Energy Technology

Geothermal energy is heat energy stored within the earth (or any otherplanet), which can be “mined” for various uses, including to produceelectricity, for direct use, or for ground-source heat pumps. Geothermalenergy sources are relatively constant with heat energy replenished onhuman time scales after being “mined,” and further require no storageother than the earth.

Potential uses of conventional geothermal energy are generallytemperature dependent, with cascading systems utilizing a singlegeothermal resource for multiple purposes. Current water-basedgeothermal systems (i.e., conventional water-based enhanced geothermalsystems (EGS) and conventional non-EGS water-based), which use water asa working fluid, require very high temperatures. For example,electricity generation at water-based geothermal power plants typicallyrequires temperatures which can exceed 150° C. Direct uses, such asaquaculture, greenhouse, industrial and agricultural processes, resorts,space and district heating (wells to structures) from such systemsutilize more moderate temperatures of about 38 to 150° C. when water isthe subsurface geothermal working fluid. Residential and commercialbuilding ground-source heat pumps from water-based geothermal systems,which may use a secondary heat exchange fluid (e.g., isobutene) in orderto transfer geothermal heat energy from the ground for use, generallyrequire temperatures between about 4 and 38° C.

DEFINITIONS

The terms “subterranean” or “subsurface” or “underground” as usedherein, refer to locations and/or geological formations beneath theEarth's surface.

The term “in situ” as used herein, refers to a natural or originalposition or place of a geologic feature which may be above ground orunderground, such that it is located in a place where it was originallyformed or deposited by nature and has remained substantially undisturbedover time, such that it is in substantially the same original condition.A geologic feature can be rock, mineral, sediment, reservoir, caprockand the like, or any combination thereof. A geologic feature is furtherconsidered to remain “in situ” following minor manmade disturbances usedto create and/or position components, such as channels such as injectionwells and/or production wells, within, around or near the feature. Afeature is also considered to remain “in situ” following minorman-initiated disturbances, such as causing a controllable or limitedamount of rock, mineral, sediment or soil to become dislodged as aresult of the minor manmade or natural disturbance. In contrast, afeature is not considered to remain “in situ” following any type oflarge-scale manmade disturbances, including large-scale hydrofracturing(such as to create an artificial reservoir), or man-initiateddisturbances, such as permanent deformation of a geologic feature,earthquakes and/or tremors following large-scale hydrofracturing, all ofwhich can have a further negative impacts on groundwater flow paths,habitats and man-made structures.

The term “large-scale hydrofracturing” as used herein refer to a knownmethod for creating or inducing artificial fractures and/or faults in afeature, such as a rock or partially consolidated sediments, typicallyduring operation of an enhanced geothermal system (EGS). See, forexample, U.S. Pat. No. 3,786,858 to Potter, which employs water forhydraulic fracturing of rock to create a thermal geological reservoirfrom which fluid is transported to the surface. Large-scalehydrofracturing is known to create unintended fluid flow pathways thatcan result in fluid loss or “shortcutting,” which in turn decreasesgeothermal heating efficiencies of the working fluid. Large-scalehydrofracturing can also cause (micro-)seismicity and damages to naturaland/or manmade structures.

The term “rock” as used herein, refers to a relatively hard, naturallyformed mineral, collection of minerals, or petrified matter. Acollection of rocks is commonly referred to as a “rock formation.”Various types of rocks have been identified on Earth, to include, forexample, igneous, metamorphic, sedimentary, and the like. A rock canerode or be subject to mass wasting to become sediment and/or soilproximate to or at a distance of many miles from its original location.

The term “sediment” as used herein, refers to a granular material erodedby forces of nature, but not yet to the point of becoming “soil.”Sediment may be found on or within the Earth's crust. A collection ofsediments is commonly referred to as a “sediment formation.” Sediment iscommonly unconsolidated, although “partially consolidated sediments” areoften referred to simply as “sediments” and are therefore considered tobe included within the definition of sediment.

The term “soil” as used herein, refers to a granular material comprisinga biologically active, porous medium. Soil is found on, or as part of,the uppermost layer of the Earth's crust and evolves through weatheringof solid materials, such as consolidated rocks, sediments, glacialtills, volcanic ash, and organic matter. Although often usedinterchangeably with the term “dirt,” dirt is technically notbiologically active.

The term “fluid” as used herein, refers to a liquid, gas, or combinationthereof, or a fluid that exists above the critical point, i.e., asupercritical fluid. A fluid is capable of flowing, expanding and/oraccommodating a shape of its physical surroundings. A fluid can comprisea native fluid, a working fluid, or combinations thereof. Examples offluid include, for example, air, water, brine (i.e., salty water),hydrocarbon, CO₂, magma, noble gases, or any combination thereof.

The term “native fluid” as used herein, refers to a fluid which isnaturally resident in a rock formation or sediment formation. A nativefluid includes, but is not limited to, water, saline water, oil, naturalgas, hydrocarbons (e.g., methane, natural gas, oil), and combinationsthereof. Carbon dioxide can also be a naturally present in the rock orsediment formation and thus constitute a native fluid in this case.

The term “working fluid” as used herein, refers to a fluid which is notnative to a rock formation or sediment formation and which may undergo aphase change from a gas to a liquid (energy source) or liquid to gas(refrigerant). A “working fluid” in a machine or in a closed loop systemis the pressurized gas or liquid which actuates the machine. A workingfluid includes, but is not limited to ammonia, sulfur dioxide, carbondioxide, and non-halogenated hydrocarbons such as methane. Water is usedas a working fluid in conventional (i.e., water-based) heat enginesystems. A working fluid includes a fluid in a supercritical state asthe term is understood in the art. Different working fluids can havedifferent thermodynamic and fluid-dynamic properties, resulting indifferent power conversion efficiencies.

The term “pore space” as used herein, refers to any space not occupiedby a solid (rock or mineral). Pore space can be the space formed betweengrains and/or the space formed by fractures, faults, fissures, conduits,caves, or any other type of non-solid space. Pore space can be connectedor unconnected and it may, or may not, evolve over time due to changesin solid space volume and/or size (which could come from reactions,deformations, etc.). A pore space is filled with fluid, as the term isunderstood in the art.

The term “CO₂ plume” as used herein, refers to a large-scale (meters toseveral kilometers to tens of kilometers in diameter) CO₂ presencewithin subsurface pore spaces (as defined above, where a significantpercentage of the fluid in the pore space is CO2.

The term “reservoir” or “storage rock formation” or “storage sedimentformation” as used herein, refers to a rock formation and/or sedimentformation capable of storing an amount of fluid substantially“permanently” as that term is understood in the geological arts.

The term “geothermal heat flow” as used herein, refers to any kind ofheat transfer in the subsurface and consists of conductive and/oradvective (sometimes referred to as convective) and/or radiative heattransfer, with radiative heat transfer typically being negligible in thesubsurface. A “low” heat flow is generally considered to be less thanabout 50 milliwatts per square meter. A “moderate” heat flow isgenerally considered to be at least about 50 to about 80 milliwatts persquare meter. A “high” heat flow is generally considered to be greaterthan 80 milliwatts per square meter.

The term “injection well” as used herein, refers to a well or boreholewhich is optionally cased (i.e., lined) and which may contain one ormore pipes through which a fluid flow (typically in a downwardlydirection) for purposes of releasing that fluid into the subsurface atsome depth. An injection well may exist in the same borehole as aproduction well.

The term “production well” as used herein, refers to a well or boreholewhich is optionally cased (i.e., lined) and which may contain one ormore pipes through which a fluid can flow (typically in an upwardlydirection) or purposes of bringing fluids up from the subsurface to(near) the Earth's surface. A production well may exist in the sameborehole as an injection well.

The term “enhanced geothermal system” (EGS) as used herein, refers to asystem in which a manmade (i.e., artificial) reservoir is created,usually by means of hydrofracturing the subsurface, i.e., inducingfractures to create space which may contain significant amounts offluid. Such artificial reservoirs are typically much smaller thannatural reservoirs

The term “conventional water-based geothermal system” as used herein,refers to a geothermal system that utilizes water as the (subsurface)working fluid. This could be in natural reservoir systems or inhydrofractured (i.e., EGS) systems.

The term “conventional CO₂-based EGS” refers to a conventional EGSsystem which uses carbon dioxide as the working fluid.

DESCRIPTION OF EMBODIMENTS

In one embodiment, a system 100 generates energy from a source, such asa carbon dioxide (CO₂) source 110 using a CO₂ sequestration component112 and a geothermal energy production component 114, as shown inFIG. 1. In one embodiment, the energy generated is thermal energy (i.e.,heat), although the invention is not so limited. In one embodiment, theenergy produced is used to generate electricity, as shown in FIG. 1. Inan alternative embodiment, the energy is drawn off as heat, as shown inFIG. 2. In yet other embodiments, the energy is used to provideelectricity and heat, as shown in FIG. 3, or to provide heat to operatea separate power cycle, such as an organic Rankine cycle, as shown inFIG. 4. Other variations and embodiments are possible, as discussedherein.

The source (e.g., CO₂ source 110) can be any suitable fluid (including afluid containing solids, in dissolved or non-dissolved form, capable ofabsorbing thermal energy from its surroundings, and further releasingthe thermal energy as described herein. In most embodiments, the sourcemay be a waste stream from a power plant, such as a fossil fuel powerplant (e.g., coal plant, natural gas plant, and the like), or any typeof plant capable of producing fuel, such as biofuel (e.g., ethanolplant) or any type of industrial plant, such as a cement manufacturer,steel manufacturer, and the like. In one embodiment, the fluid isfurther capable of being transported via any suitable means, (e.g.,pipe, various transportation means, such as truck, ship or rail), over adesired distance. Although the source, such as the CO₂ source 110 can,in most instances, be used “as is”, in some instances, furtherprocessing may be used prior to introducing the CO₂ source 110 to acompressor 132 to produce a working fluid, such as cold CO₂ 138, asshown in FIG. 1. For example, some waste streams may require dewateringand/or drying. In one embodiment the CO₂ source 110 is stored on site oroff site for a period of time. In one embodiment, the cold CO₂ 138 issupercritical CO₂.

In one embodiment, the system 100 is located at a site (i.e., in aposition) configured to provide access to a target formation, the targetformation comprising a caprock 118 located above a reservoir 120 asshown in FIG. 1. In one embodiment, the reservoir 120 has a naturaltemperature higher than a temperature of the working fluid. In theembodiment shown in FIG. 1, the natural temperature in the reservoir 120is affected by geothermal heat 124 flowing up from below.

A top layer 116 may be located above the caprock 118 and reservoir 120as shown in FIG. 1. The top layer 116 may comprise any number of layersand types of natural deposits and/or formations. For example, the toplayer 116 may contain one or more features such as a reservoir (e.g.,reservoir 120) or caprock (e.g., caprock 118) having the features asdescribed herein. In one embodiment, the top layer 116 additionally oralternatively contains additional areas suitable for injection of theworking fluid, such as the cold CO₂ 138 shown in FIG. 1. In oneembodiment, the top layer 116 additionally or alternatively furthercomprises any type of rocks, including rocks or sediments in layers,rock or sediment formations, and the like, or any combinations thereof.In one embodiment, the top layer 116 additionally or alternativelycomprises a top layer or layers of sediment and/or soil of varyingdepths. The permeability and/or porosity of the top layer 116 may varywidely, as long as drilling can be performed to insert the injectionwell 136 and production well 160 as described below, without usinglarge-scale hydrofracturing.

In one embodiment, the top layer 116 can include a variety of geologicfeatures, including, but not limited to, soil, sand, dirt, sediment, andthe like, or combinations thereof. The top layer 116 may further have awide range of depths (i.e., “thickness”) sufficient to ensure workingfluid introduced into the reservoir 120 remains in the desired state,such as a supercritical state. In one embodiment, the depth of the toplayer 116 is at least 100 meters (m) or more, up to one (1) kilometer(km), further including more than one (1) km, such as up to three (3)km, four (4) km, five (5) km, or more, such as up to 10 km or over 15 kmincluding any range there between, such as one (1) to five (5) km, belowthe Earth's surface (i.e., below or within a given topography in anarea, which may or may not be exposed to the atmosphere). In mostembodiments, however, it is expected that the target formations arelocated between about 800 m and about four (4) km beneath the Earth'ssurface.

Factors that can be considered in selecting reservoir depths can alsovary according to local geology (e.g., specific rock type, geothermalheat flow rates, subsurface temperatures), access to working fluid(e.g., carbon dioxide from fossil fuel burning power plants, ethanolplants), drilling and operation costs, and sociopolitical circumstances(e.g., consumer locations, constructs, electric grid locations, and thelike).

The target formation, comprising the caprock 118 and reservoir 120, canbe made up of a variety of rock types, including, but not limited to,igneous rock, metamorphic rock, limestone, sedimentary rock, crystallinerock, and combinations thereof. In one embodiment, the target formationis a sedimentary basin having a substantially bowl or convex shape asshown in FIG. 4. In other embodiments, the target formation have anothershape, such as the substantially dome or concave shape as shown in FIGS.1-3, although the invention is not limited to the shapes depicted inFIGS. 1-4. In one embodiment, the target formation is a saline aquiferor a saline water-filled rock formation (e.g., reservoir 120) containinga native fluid which is inhibited or prevented from escaping upwardly,due to the presence of the caprock 118. It is further understood that atarget formation may contain a fault which can offset the targetformation or a portion of the target formation, thereby forming ageological trap, as the term is understood in the art. In anotherembodiment, the target formation is a reservoir containing natural gasand/or oil and/or fresh water.

In one embodiment, CO₂, such as the cold CO₂ 138 shown in FIG. 1, isused as the working fluid in combination with a reservoir 120 located atleast about 0.1 km, to about 4 km deep. Such a combination can minimizeupward leakage of the working fluid, since additional caprocks 118 maybe present between the reservoir 120 and the Earth's surface.Additionally, higher natural reservoir temperatures (i.e., greater thanabout 70° C.) and higher pressures (i.e., greater than about 8 MPa) maybe encountered at such depths. Larger depths can also increase thelikelihood of the presence of dissolved salts and other minerals in thenative fluid, which may reduce the likelihood that such native fluidwould otherwise be useful for drinking and irrigation applications.

The caprock 118 shown in FIG. 1 is a geologic feature having a very lowpermeability, i.e., below about 10⁻¹⁶ m². Such a low permeability allowsthe caprock 118 to essentially function as a barrier for fluid containedin the reservoir 120 below. Permeability may also be dependent, in part,on the depth (i.e., thickness) of the caprock 118, as well as the depthof the top layer 116 above. The porosity of the caprock 118 can varywidely. As is known in the art, even if a rock is highly porous, ifvoids within the rock are not interconnected, fluids within the closed,isolated pores cannot move. Therefore, as long as the caprock 118exhibits permeability sufficiently low to allow it to prevent or inhibitfluid leakage from fluid in the reservoir 120, the porosity of thecaprock 118 is not limited.

The thickness of the caprock 118 can vary, but is generallysubstantially less than the thickness of the top layer 116. In oneembodiment, the top layer 116 has a thickness on the order of 10, or 10to 100, up to 1000 times the thickness of the caprock 118, furtherincluding any range there between, although the invention is not solimited. In one embodiment, the thickness of the caprock 118 can varyfrom about one (1) cm up to about 1000 m or more, such as between aboutfive (5) cm and 1000 m, such as between about one (1) m and about 100 m.In one embodiment, the caprock 118 represents more than one caprock 118,such that multiple caprocks are present which partially or completelycover one another and may act jointly as a caprock 118 to prevent orreduce upward leakage of the working fluid from the reservoir 120.

The reservoir 120 can be one or more natural underground rock reservoirscapable of containing fluids. In one embodiment, the reservoir 120 is apreviously-created manmade reservoir or a portion of apreviously-created manmade reservoir, such as, for example, shaleformations remaining from shale fracturing for hydrocarbon removal. Inone embodiment, the reservoir 120 is also capable of storing carbondioxide on a substantially “permanent” basis, as this term is understoodin the art. In most embodiments, the reservoir 120 is sufficientlyporous and permeable to be able to sequester fluids, such as carbondioxide, and to receive and retain geothermal heat 124. In contrast toconventional enhanced geothermal systems, there is no requirement thatthe reservoir 120 be a hot dry rock reservoir, as that term isunderstood in the art, although, as noted herein, the such a reservoircan optionally be used

In one embodiment, the reservoir 120 is sufficiently permeable to allowmultidirectional routes for dispersion or flow of fluid at relativelyhigh rates, including lateral dispersion or flow. The presence of thecaprock 118 above the reservoir 120 further enhances the dispersioncapabilities of the reservoir 120. In one embodiment, the porosity ofthe reservoir 120 ranges from between about four (4) % to about 50% orgreater, such as up to about 60%.

The reservoir 120 is also sufficiently permeable to allow fluids to flowrelatively easily, i.e., at a rate of about 0.1 to about 50liters/minute (L/min). In one embodiment, the reservoir 120 has apermeability of about 10⁻¹⁶ m² to about 10⁻⁹ m², or greater, such as upto about 10⁻⁶ m².

In an exemplary embodiment, the reservoir 120 has a porosity of at leastabout (4) % and a permeability of at least about 10⁻¹⁵ m², with thecaprock 118 having a maximum permeability of about 10⁻¹⁶ m². (See alsoExample 1).

The reservoir 120 can have any suitable natural temperature. In oneembodiment, the natural temperature of the reservoir 120 is at leastabout 90° C., although the invention is not so limited. In oneembodiment, natural temperatures below 90° C., such as down to 80° C. or70° C., further including down to 30° C., including any range therebetween, are present. Natural temperatures greater than 90° C. may alsobe present, with the highest temperature limited only by the amount ofgeothermal heat 124 provided and the ability of the reservoir 120 tocapture and retain the geothermal heat 124. It is possible thattemperatures greater than about 300° C. may be present in the reservoir120.

In one embodiment, a specific desired natural temperature is obtained byvarying the depth of the injection well 136 or the production well(i.e., recovery well) 160. In one embodiment, higher naturaltemperatures are obtained by increasing the depth of the injection well136, with or without increasing the depth of the production well 160.Unlike conventional geothermal energy systems which utilize water as theworking fluid, however, the natural temperatures used to generate energyin the novel non-water based geothermal systems described herein, inamounts sufficient to produce electricity, for example, are much lower.

The depth of the reservoir 120 can vary as noted above. Additionally,the overall size of the reservoir 120 can also vary.

The geothermal heat 124 can flow at any suitable rate, including at ahigh rate as is present in “high geothermal heat flow regions”, as theterm is understood in the art. Conventional water-based systems areknown to require high geothermal heat flow in most instances. As aresult, as compared to conventional systems using water as the workingfluid, the novel systems described herein can operate in a wider rangeof locations, including low and moderate geothermal heat flow regions.Also in contrast to conventional water-based systems which may choose tooperate in areas containing little natural water (e.g., AmericanSouthwest), thus requiring importation of water, the novel systemsdescribed herein do not rely on water as the working fluid, and thus donot import water for use as a working fluid. It is to be understood,that areas having medium or low geothermal heat flow rates can also beused.

Additionally, water in a conventional EGS tends to react extensivelywith rocks causing mineral precipitation and/or wall rock dissolutionreactions. In contrast, substantially pure CO₂ (for example, CO₂ in thecenter of the CO₂ plume 122) is expected to result in very limited to norock/mineral-fluid reactions. Some limited reactions may occur at the(narrow) H₂O—CO₂ interface. Extensive fluid-mineral/rock interactionscan have often have adverse effects due to fluid flow pathmodifications, since flow constrictions can be formed due tomineral/rock/sediment precipitations with “short-circuiting” resultingfrom mineral/rock/sediment dissolution. However, limited reactions canhave beneficial effects in the form of permeability and/or porosityenhancement.

As noted above, the system 100 of FIG. 1 comprises a CO₂ sequestrationcomponent 112 and a geothermal energy production component 114. CO₂sequestration is accomplished by providing the CO₂ source 110 to anoptional compressor 132 to produce compressed CO₂ 111 (i.e., CO₂ havinga temperature of about zero (0) to about 50° C. and pressure of aboutthree (3) to about seven (7) MPa). The compressed CO₂ 111 can optionallypass through a first cooling unit 134 to produce a working fluid, suchas cold CO₂ 138 (i.e., saturated liquid CO₂ having a temperature lessthan about 30° C. and pressure of about three (3) to about seven (7)MPa), before entering the injection well 136, as shown in FIG. 1, whereit flows in a substantially downwardly direction below the Earth'ssurface. Upon its release at an injection well reservoir opening 170,the cold CO₂ 138 permeates the reservoir 120 forming a CO2 plume. Uponexposure to the temperatures present in the reservoir 120 (which arehigher than the temperature of the cold CO₂ 138), the cold CO₂ 138absorbs heat from the reservoir 120, thus causing an upwardly-migratingCO₂ plume 122, which, in one embodiment, may be laterally advected dueto non-zero groundwater flow velocities within the reservoir 120, asshown in FIG. 1. In one embodiment, lateral migration occursadditionally or alternatively due to the CO₂ plume spreading, asadditional CO₂ exits the injection well 170.

The CO₂ plume 122, which can further contain an amount of native fluid(partially dissolved in the CO₂ plume or included as individual bubblesor fluid pockets), migrates, is transported (such as in a closed loopsystem as described herein) and/or flows and/or spreads towards theproduction well 160, entering a production well reservoir opening 172 ashot CO₂ 140 (i.e., fluid CO₂ having a temperature greater than about 30°C.). The CO₂ plume 122 can move at any suitable rate in a substantiallyhorizontal manner across the reservoir 120. In one embodiment, the CO₂plume 122 moves at a rate of about 0.1 to about one (1) m/day, such asabout 0.4 to about 0.6 m/day, although the invention is not so limited.When the CO₂ plume 122 reaches the production well reservoir opening 172as hot CO₂ 140, it can be transported and/or buoyantly move in agenerally upwardly direction towards the Earth's surface. In theembodiment shown in FIG. 1, the hot CO₂ 140 enters an expansion device142 to produce shaft power 144 which can be provided to a generator 146to produce electricity 148 and to the compressor 132.

Warm CO₂ 150 (i.e., gaseous CO₂ having a temperature between about zero0° and about 30° C. and a pressure between about three (3) and aboutseven (7) MPa) is also drawn off the expansion device 142 for use withinthe system 100, to provide part of the required load used duringoperation, thus providing a “power cycle.” As such, the warm CO₂ 150 isprovided to the second cooling unit 152, where exhaust 154 (warmed airor water or water vapor) is released, while cooled CO₂ 157 can beprovided to the first cooling unit 134 to repeat the power cycle, afteroptionally passing through a pump 156.

A variety of working fluids can be employed in the novel systems andmethods described herein. The working fluid used in the carbon dioxidesequestration component 112 of the system 100 shown in FIG. 1, is coldCO₂ 138 obtained from a CO₂ source 110. Such a working fluid can furthercontain entrained contaminants. In contrast, the working fluid useful inthe substantially above-ground geothermal energy production component114 of the system 100 may be any suitable secondary working fluid 250 asis understood in the art. (See FIGS. 2-4). In one embodiment, theworking fluid for either the CO₂ sequestration component 112 or thegeothermal energy production component 114 with a non water-based fluid,i.e., any fluid which is thermodynamically more favorable than water(i.e., having a higher condensing pressure and higher vapor density atambient temperature). In one embodiment, one or more supercriticalfluids are used as the working fluid for either or both components, 112and 114.

In a particular embodiment, supercritical carbon dioxide is used as theworking fluid in the CO₂ sequestration component 112 and/or thegeothermal energy production component 114. Supercritical carbon dioxidehas an increased density, as compared with other working fluids, such asgaseous carbon dioxide, such that a greater amount can be stored in asmaller volume, thus increasing system efficiency. Additionally, and inparticular for the CO₂ sequestration component 112, supercritical carbondioxide has favorable chemical properties and interactioncharacteristics with water (such as saline water), as is known in theart. Supercritical carbon dioxide can also be used in colder conditions,as compared with water-based geothermal systems, since it has a lowerfreezing point of about −55° C. (as compared to approximately 0° C. forwater) depending on pressure. As such, a carbon dioxide-based system canbe used in temperatures much lower than 0° C., such as down to −10° C.or −20° C. or −30° C. or below, down to about −55° C., including anyrange there between. A larger temperature differential between the heatsink (atmosphere or ambient air) and the heat source (reservoir 120),also increases the overall efficiency of the system. The use of carbondioxide, in one embodiment, as the working fluid in the CO₂sequestration component 112 allows for sequestering of carbon dioxide.

In one embodiment, the working fluid in the CO₂ sequestration component112 (e.g., cold CO₂ 138) is released directly into the reservoir 120where it becomes a CO₂ plume 122, which is allowed to flow throughnatural pores, fractures and conduits present in the reservoir 120 inthe area between the injection well reservoir opening 170, where iteventually becomes hot CO₂ 140, before entering a production wellreservoir opening 172 of the production well 160, as shown in FIG. 1.Such a flow pattern is referred to herein as an “open” flow cycle. Inthis embodiment, the working fluid can displace and/or commingle withany native fluid(s) present. In this embodiment, heat exchange betweenthe reservoir 120 and the working fluid (e.g., cold CO₂ 138) isfacilitated and heat energy extraction is increased, as compared to a“closed” system in which the working fluid travels only through manmadepipes located in the reservoir 120 between the injection well reservoiropening 170 and the production well reservoir opening 172. Additionally,any fluid loss occurring in an open cycle is simply sequestered in thereservoir 120. In one embodiment, a partially open cycle is used. In oneembodiment a closed cycle is used. The injection well reservoir opening170 and the production well reservoir opening 172, the production well160 are, in one embodiment, located at a distance sufficiently apartfrom one another to permit adequate heating of the cold CO₂ 138 to thedesired temperature.

The compressor 132 can comprise any suitable compressor or compressorsknown in the art. In one embodiment any suitable type of pump replacesthe compressor 132. In one embodiment, no compressor 132 is used, suchas when the CO₂ source 110 is provided at a sufficiently high pressure(i.e., greater than about six (6) MPa). In one embodiment, no compressor132 (or pump) is used and the first cooling unit 134 is a condenserwhich provides a saturated liquid at ambient temperature andcorresponding saturation pressure (e.g., CO2) for injection into theinjection well 136, thus maximizing the density of the working fluid aswell as the thermosyphon effect within the injection well 136.

In one embodiment, when the ambient temperature rises, and thus thecorresponding saturation pressure also rises in the condenser or secondcooling unit 152, the decrease in liquid density provided to theinjection well reduces the hydrostatic head in the injection well. Inone embodiment, as described in the Example section, the highercondensing pressure surprisingly compensates for this decreased densityeffect at a level sufficient to maintain the deep rock cavity (i.e.,reservoir 120) pressure regardless of changing surface conditionswithout using a compressor 132 (or pump). Such a configuration allowsfor reduced start-up and operating costs.

Use of the first cooling unit 134 ensures that all of the carbon dioxideinjected into the injection well 136 will be fluid at the same pressureand temperature, regardless of whether it comes from the CO₂ source 110or as cooled CO₂ 157 from the power cycle. Any suitable type or types ofcooling unit can be used for the first cooling unit 134. The firstcooling unit 134 further minimizes the amount of pumping action neededto increase pressure at the injection well 136, since less power isneeded to pump a liquid to a higher pressure than a gas. Use of thefirst cooling unit 134 also helps to maximize any natural thermosyphoneffect present (i.e., passive heat exchange based on natural convectionwhich circulates liquid), by providing the injection well 136 with coldCO₂ 138 at all times, although the invention is not so limited. In oneembodiment, there is no first cooling unit 134. In one embodiment, thefirst cooling unit 134 is a condenser cooled by any suitable coolingmeans, such as with a water-antifreeze solution (e.g., glycol), with thecooling means in turn cooled by ambient air in the condenser.

The injection well 136 can be any suitable type of channel that allowsthe working fluid to move substantially downwardly. In one embodiment,the injection well 136 comprises more than one injection well. Dependingon a particular site's history of heat extraction and on the geologiccircumstances in the area (e.g., geologic layers at depth, geothermaltemperatures and heat flow rates), as well as the socio-politicalcircumstances (instance to users and/or electrical grid, CO₂ sourceavailability and distance, etc.), multiple injection wells may belocated in patterns and inject the working fluid (CO₂) at various depthsand rates to maximize the energy output of the power plant, maximize CO₂sequestration, minimize subsurface heat depletion or a combinationthereof.

In one embodiment, the injection well 136 and the production well 160comprise a single channel or shaft with two or more pipes extendingthere from. In this embodiment, the injection “pipe” is deeper than theproduction “pipe.”

Similarly, the production well 160 can be any suitable type of channelthat allows the working fluid to move substantially upwardly. In oneembodiment, the production well 160 comprises more than one productionwell. As with the injection well 136, patterns, depths, and CO₂extraction rates of the production well 160 may be optimized.

In one embodiment, the injection well 136 comprises more than oneinjection well distributed in various locations and one or moreproduction wells 160 are more centrally located. In this embodiment, theambient temperature liquid coming out of the first cooling unit 134 canbe provided to the sites of the various injection wells 136 throughgravity-sloped small pipes (e.g., high density, low volumetric flowrate) with little or no thermal insulation required. The hot vapor, suchas the hot CO₂ 140 in the production well 160 is provided more directlyto the geothermal energy production component 114, wherein pipe sizesmay need to be larger to handle the higher volumetric flow rate andthermal insulation required.

The locations of the injection well 136 in relation to the productionwell 136 can be determined by any suitable means, including accessinggeological data, such as from the U.S. Geological Survey pertaining tothe particular target formation, and performing computer modeling, suchas described in the Example section, in order to be able to predict andoptimize conditions within the reservoir 120, such that, for example,the production well reservoir opening 172 of the production well 160 isat a point where the CO₂ plume 122 is at a sufficiently high temperatureto become hot CO₂ 140. In one embodiment, the injection well 136 andproduction well 160 are located at a distance sufficient to ensure thatthe working fluid (e.g., the cold CO₂ 138) increases in temperature byat least about 10° C. from the injection well reservoir opening 170 andthe production well reservoir opening 172. Such distance can be alateral distance, a vertical distance, or a combination thereof.

In one embodiment, the roles of the injection and production wells, 136and 160, respectively, are reversed after a period of time to improvesubsurface heat exchange within the reservoir 120. In one embodiment,the injection and production wells are reversed every few months orabout every one (1) year up to about every five (5) years or any periodthere between.

The expansion device 142 can comprise any suitable type of expansiondevice 142 known in the art, including any type of turbine, although theinvention is not so limited. In contrast to conventional water-basedgeothermal systems which produce low pressure steam at high volumetricflow rates, the use of a conventional turbine in higher pressure CO₂geothermal energy systems and methods described herein, is an option,rather than a requirement

In one embodiment, the expansion device 142 is one or morepiston-cylinder devices. In one embodiment, the expansion device 142 isone or more scroll, screw or rotary compressors designed to run inreverse as engines. In one embodiment, the expansion device 142comprises more than one expansion device 142. In one embodiment,multiple expansion devices 142 run in parallel, with some running pumpsor compressors directly and others producing electric power for sale.

The generator 146 can be any suitable generator known in the art, toproduce electricity 148. The second cooling unit 152 can be any suitabletype of cooling unit as is known in the art. In one embodiment, thesecond cooling unit 152 is a dry cooling tower in which the exhaust 154is released to ambient air. In one embodiment, the second cooling unit152 is a wet cooling tower in which the exhaust 154 is released into theair by also evaporating a volume of water. In one embodiment, a drycooling tower is used during colder conditions and a wet cooling toweris used during warmer conditions. Use of a wet cooling tower duringwarmer conditions can increase plant efficiency, as is known in the art.

The pump 156 shown in FIG. 1 is also optional and may be any suitabletype of pump 156 as is known in the art to move the cooled CO₂ 157(e.g., direct lift, displacement, velocity, buoyancy, gravity, and thelike) exiting the second cooling unit 152 prior to its return to thefirst cooling unit 134.

In an alternative embodiment, the reservoir 120 is also used as acooling unit to cool warm CO₂ 150 exiting the expansion device 142, withthe appropriate piping and pumps provided as is known in the art.

In one embodiment, a geothermal energy system is provided, comprising asubterranean fluid transport system comprising an ingress channel (intothe reservoir) and egress channel (out of the reservoir), each of theingress and egress channels having respective proximal ends and distalends relative to the surface; a natural subterranean porous in situ rockformation; a working fluid, the supercritical fluid being introducedinto the rock formation starting at the proximal end and moving towardthe distal end of the ingress channel. The fluid is withdrawn in part atthe distal end of the ingress channel so as to form a subterranean fluidreservoir integral with the rock formation; and wherein the fluid isheated by the rock formation prior to transport toward the surface andproximal end 1 of the egress channel.

The system can comprise a compressor located in-line and integrated aspart of the ingress channel to facilitate movement of the fluid towardthe rock formation (i.e., reintroduction). The heated plume is formed aspart of the migration through the rock toward the intake at the egresschannel distal end. In the interim, the fluid absorbs the naturalgeothermal heat associated with the rock formation. Once the heatedfluid travels toward the surface, the egress channel proximal end can beassociated with a turbine and generator system, whereby electricalenergy is produced and distributed to the consumer(s). Alternatively,the heat energy can be incorporated into system for district space andwater heating applications (not illustrated).

In one embodiment, the subsurface-heated working fluid, as a primaryworking fluid, can be directly introduced into a turbine assembly aspart of a turbine-generator system to generate electricity. In thisembodiment, it is preferable to remove water or other ingredients asmight be present within the primary working fluid.

In an additional embodiment, a plurality of ingress channels can beemployed in combination with a single egress channel. Alternatively, aplurality of egress channels can be constructed, using a single ingresschannel. Further yet, both a plurality of ingress channels and aplurality of egress channels can be constructed within a unitary system.Various arrangements are possible with the invention. Arrangements usingmultiple systems at a land surface area using different parts of thesame rock formation strata, or using separate and distinct rockformations at different depth and space parameters are contemplated.

In an additional embodiment of the invention, an additional transportchannel can be constructed for the transport of external carbon dioxidesources. Examples of external carbon dioxide sources include, but arenot limited to, fossil fuel power plants, ethanol plants, and the like.When direct turbine-generator systems are used, a water removalcomponent may be incorporated into the system.

In one embodiment, the novel systems and methods described herein areconstructed to permit maintenance desired for optimal operation of thesystem. For example, the working fluid supply channel (ingress channel)can be structured to permit its removal for maintenance (e.g.,cleaning), or intermittent removal for a period of time to create atemporary closed cyclic system. The system can also be constructed toreceive and accommodate multiple industrial carbon dioxide supply linesfrom different sources as part of the system.

In an alternative embodiment, as shown in FIG. 2, the hot CO₂ 140 passesthrough a heat exchanger 202 where it is used to warm a secondaryworking fluid 250 also cycling through the heat exchanger 202 (throughthe second cooling unit 152 and pump 255 as shown). The heated secondaryworking fluid (temp >about 30° C.) is released as heat 204, which can beused in any direct use application and/or as a ground-source heat pump,using components well known in the art. A portion of the heatedsecondary working fluid enters the expansion device 142 to produce shaftpower 144 which is provided to the compressor 132 where the cycle isrepeated. Meanwhile, the hot CO₂ 140 exits the heat exchanger 202 ascooled CO₂ 159 (i.e., CO₂ having a temperature of two (2) and seven (7)MPa that may be condensed liquid), passing through an optional pump orcompressor 156 and finally returned to the first cooling unit 134, whereit may be further cooled to become cold CO₂ 138, thus repeating thecycle.

In another alternative embodiment, as shown in FIG. 3, both electricity148 and heat 204 are produced. In this embodiment a second cooling unit(not shown) (e.g., 152 in FIGS. 1 and 2) is used and the heat exchanger202 as described above is also retained.

In another alternative embodiment, as shown in FIG. 4, electricity 148is produced and the a portion of the heat exiting the heat exchanger 202is provided to a separate Rankine power cycle 405 having the componentsas understood in the art. With a Rankine cycle 405, the condensingpressure is typically subcritical and the highest pressure during theheat addition may be either supercritical or subcritical.

In one embodiment, a novel method is provided comprising pumping CO₂from an emitter (e.g., ethanol or coal-fired power plant) undergroundinto a geothermal reservoir. At certain depths (e.g., about 0.4 to abouttwo (2) km), the reservoir contains salty groundwater unlikely to beused for irrigation or consumption. Alternatively, the reservoir maycontain hydrocarbons (oil, natural gas) and the injected CO₂ issupercritical CO₂ which serves to enhance oil recovery (EOR). As notedabove, the target formation comprises a reservoir located underneath atleast one very low permeability caprock that prevents the working fluid,e.g., supercritical CO₂, from rising to the surface (similar to anatural gas trap). In addition, the depth of the reservoir reduces thechance of CO₂ reaching the surface, as multiple other low-permeabilitylayers are likely present above the reservoir.

In one embodiment, CO₂ in the reservoir is heated by Earth's geothermalheat flow, which partially replenishes the heat energy transmitted tothe CO₂. In one embodiment, a small portion of the geothermally-heatedCO₂ is brought back to the surface where it drives an expansion deviceand generator, such as a turbine-generator combination. The cooled CO₂can thereafter be returned to the reservoir. In one embodiment, theenergy used to pump the CO₂ to the subsurface is a small fraction (e.g.,substantially zero (0) % to about five (5) %) of the energy provided bythe geothermal heat and may also be small in comparison to theelectricity produced by the system (e.g. substantially zero (0) % toabout 25%).

The various individual components of the system of the invention can beobtained and constructed using conventional equipment and techniquesreadily available to those in the (geothermal) power plant and carbondioxide sequestration industries. Site locations can be determined usinggeological survey data for various regions throughout a given country incombination with the porosity and permeability parameters describedherein as suitable for the method and system of the invention.

The specific materials and designs of additional minor componentsnecessary to perform the process, e.g., valves, pumps, lines, and thelike, are understood in the art will not be described herein. Theapparatus and method of the invention can further be implemented using avariety of specific equipment available to and understood by thoseskilled in process control art. For example, means for sensingtemperature, pressure and flow rates in all of the flow lines may beaccomplished by any suitable means. It will also be appreciated by thoseskilled in the art that the invention can include a system controller.

Specifically, the system controller can be coupled to various sensingdevices to monitor certain variables or physical phenomena, process thevariables, and output control signals to control devices to takenecessary actions when the variable levels exceed or drop below selectedor predetermined values. Such amounts are dependent on other variables,and may be varied as desired by using the input device of thecontroller. Such sensing devices may include, but are not limited to,devices for sensing temperatures, pressures and flow rates, andtransducing the same into proportional electrical signals fortransmission to readout or control devices may be provided for in all ofthe principal fluid flow lines. Such a controller may be a local orremote receiver only, or a computer, such as a laptop or personalcomputer as is well-known in the art. In one embodiment, the controlleris a personal computer having all necessary components for processinginput signals and generating appropriate output signals as is understoodin the art. These components can include a processor, a utility, adriver, an event queue, an application, and so forth, although theinvention is not so limited. In one embodiment, the controller has anon-volatile memory comprised of a disk drive or read only memory devicethat stores a program to implement the above control and storeappropriate values for comparison with the process variables as is wellknown in the art.

In one embodiment, these components are all computer programs executedby a processor of the computer, which operates under the control ofcomputer instructions, typically stored in a computer-readable mediasuch as a memory. In this way, useful operations on data and other inputsignals can be provided by the computer's processor. The controller alsodesirably includes an operating system for running the computerprograms, as can be appreciated by those within the art. The systemcontroller may also comprise a machine coupled to a control panel.Buttons and dials can be provided on the control panel to allowmodification of the values and to control of the carbon dioxide-basedenergy generating system to take the desired steps described herein. Thesystem controller can also be programmed to ignore data from the varioussensors when the operator activates certain other buttons and dials onthe control panel as he/she deems necessary, such as fill override oremergency stop buttons. Alternatively, or in addition to the foregoing,the control panel can include indicator lights or digital displays tosignal an operator as to the status of the operation. Indicator lightscan also be used to signal that a certain variable level is outside thedesired range, therefore alerting the operator to the need forcorrective action. In such an embodiment, the corrective action is notautomatic, but requires the operator (who may be located remotely andoptionally controlling more than one system substantiallysimultaneously) to initiate corrective action either by pushing aspecific button or turning a specific dial on the control panel, or bymanually adjusting the appropriate valve or device.

Additionally, as is known in the art, in implementing the systemdescribed herein, general chemical, mechanical and physical engineeringprinciples must be adhered to, including accounting for the varioustypes of energy and materials being input to and output from the system,in order to properly size the system. This includes not only the energyassociated with mass flow, but also energy transferred by heat and work.In some embodiments, the system is optimized for maximum performanceutilizing any known optimization methods known in the art.

The invention will be further described by reference to the followingexamples, which are offered to further illustrate various embodiments ofthe present invention. It should be understood, however, that manyvariations and modifications may be made while remaining within thescope of the present invention.

Example 1

Numerical modeling of carbon dioxide migration and storage was conductedusing two-dimensional solute (carbon dioxide) injection schemesemploying the multiphysics modeling environment COMSOL™ (available fromComsol AB, Burlington, Mass.).

A generic cross-section of Minnesota's Rift System (MRS) was provided bythe Minnesota Geological Survey (MGS) and is shown in FIG. 5. FIG. 6provides an enlarged view of a portion of FIG. 5, taken from within box6-6, which is an area that includes the Oronto Group of geologicalformations, estimated to be about 2.65 million years old. Within theOronto Group, an area is noted that contains a target formation 600which includes a caprock 618 and an aquifer 620 which was used for anumerical model of an energy generation system, as described herein. Themodel can permit estimation of the potential of the Midcontinent RiftSystem (MRS) for a carbon plume geothermal (CPG) system and the amountof time required for carbon dioxide to move from an injection to aproduction well.

A carbon dioxide injection model was designed and used to evaluate thespread of injected material over time and to determine whether thecaprock 618 can effectively seal a reservoir, such as the aquifer 620shown in FIG. 6.

FIG. 7 is an illustration of the target formation 600, containing thecaprock 618 and aquifer 620. A simulated injection well 736 can be seenwithin the aquifer 620. Since no deep wells exist in Minnesota toprovide geometric configurations of aquifer and caprock units, thecross-section was used only to verify that the estimated rift structurewas sufficiently deep for carbon dioxide storage and to estimate depthsfor storage units. Due to the lack of measured data, a rectangularaquifer 50 meters (m) thick (in height) and several km in length wasassumed and illustrated in FIG. 7.

The model geology was expanded by placing a capping material, i.e.,caprock 618 dimensionally equivalent to the aquifer 620, immediatelyabove the aquifer 620. The aquifer and caprock are then encased in asurrounding material that extends vertically to the ground surface withthe aquifer at a depth of about 2500 m, and horizontally severalkilometers beyond the aquifer and caprock (See, for example, FIG. 6).The extent of surrounding material was chosen such that the upper andlower boundaries were far enough from the aquifer to realisticallyassume that no fluid flow occurs across the boundaries during thesimulated time interval while the left and right boundaries were chosento be sufficiently far from the modeling domain of interest to assumehydrostatic fluid pressure conditions (i.e., constant pre-injectionfluid pressure conditions). The surrounding unit's permeability wasvalued at 10¹⁹ m², and the pore fraction was 0.04 (i.e., 4%) based onthe data provided by the MGS. Fluid flow was permitted through the topand bottom of the aquifer to simulate natural conditions.

A solute solution of one (1) % CO₂ was injected (the remaining contentbeing water), with a solute weight approximately equivalent tosupercritical CO₂ at a depth of 2500 m, in the center of the aquifer fora period of one year. The injection rate can be varied to approximateinjection of all CO₂ produced by a large (e.g., about 250 megawatt (MW)to about 1000 MW) fossil fuel-fired power plant. Carbon dioxide as asolute in water was assumed for injection into a water aquifer becausethe solute approach simplified modeling as compared with pure carbondioxide fluid. Future modeling may include use of pure carbon dioxidefluid.

Approximately 30 scenarios were run (see FIG. 8 for a visualization of asample injection), with varying injection rates and aquifer and caprockpermeabilities and porosities. The results are set forth below in Table1.

TABLE 1 Injection Rates and Aquifer and Caprock Permeabilities andPorosities Max concentration of solute Leakage in aquifer through [unitsof kg/m³] caprock Porosity of aquifer Distance in aquifer from injectionwell horizontally to liquid with a concentration of 1 kg/m³ [m] Valueused 0.1 when other parameters are varied: Range: 0.02 150 14000 Yes0.04 150 13139 No 0.06 150 11588 No 0.08 150 10214 No 0.1 150 9075 No0.12 150 8150 No 0.14 150 7391 No 0.16 150 6749 No 0.18 150 6225 No 0.2150 5761 No Permeability of aquifer Value used 10⁻¹³ m² when otherparameters are varied Range: 10⁻¹³ 150 9075 No 10⁻¹⁴ 153 8927 No 10⁻¹⁵186 7665 Some 10⁻¹⁶ 430 3656 Some 10⁻¹⁷ 1261 1167 Yes 10⁻¹⁸ 3472 360 Yes10⁻¹⁹ 14080 170 Yes 10⁻²⁰ 62970 123 Yes Porosity of caprock Distance inaquifer from injection well horizontally to liquid with a concentrationof 1 kg/m³ Value used 0.08 when other parameters are varied Range: 0.02150 9160 Yes 0.04 150 9133 Yes 0.06 150 9101 Some 0.08 150 9075 No 0.1150 9031 No 0.12 150 9024 No 0.14 150 8997 No 0.16 150 8963 NoPermeability of caprock Value used 10⁻¹⁸ m² when other parameters arevaried Range: 10⁻¹⁸ 150 9075 No 10⁻¹⁹ 158 8904 No 10⁻²⁰ 192 7820 No10⁻²¹ 317 5684 No Pumping rate Value used 5 m³/s when other parametersare varied Range: 5 150 9075 No 10 292 9101 No 15 499 9134 No 20 6239150 Some

The model indicated that the matrix permeability of the caprock in therift was sufficiently low, ranging between 10⁻²¹ m² to 10⁻¹⁸ m². Thiswas sufficient to serve as an effective reservoir caprock in the absenceof large-scale hydrofracturing. Furthermore, deep geologicalsequestration and carbon plume geothermal (CPG) system would be possiblein the reservoir of the rift, provided that large sandstone bodies withporosities in the range of 0.04 to 0.2 (i.e., about four (4) % to 20%)and permeabilities in the range of 10⁻¹⁵ m² to 10¹³ m² (with anuncertainty of about a factor of 10) would eventually be located in therift at depths greater than 800 m below a caprock with the aboveproperties.

The model also indicated that the horizontal spread of solute wasgenerally less than about ten (10) km from the injection point, which isa relatively small distance, and the result was interpreted to indicatereasonable storage space for aquifers having the previously definedproperties. The results also suggest that in a CPG scenario, carbondioxide would travel from injection to production wells, which could bea few hundred meters to several kilometers apart, within a relativelyshort period of time (typically less than a year to a maximum ofapproximately three (3) years).

Additional modeling demonstrated that the porosity of caprock units canbe in a range from between about 0.06 to about 0.16 (i.e., about six (6)% to about 16%, respectively). Note that this range overlaps with thatof the aquifer porosity. The models also indicated that porosity overlapwould not be problematic for carbon dioxide storage, provided caprockpermeability is several orders of magnitude lower than aquiferpermeability. This preliminary study further provides support forproviding a single injection well to accommodate all the carbon dioxideproduced by an approximately 1000 MW coal-fired power plant using thenovel systems described herein.

These results provide support for using a reservoir having a porosity ofat least about (4) % and a permeability of at least about 10⁻¹⁵ m² orgreater for sequestration within the MRS assuming presence of a caprockhaving a maximum permeability of about 10⁻¹⁸ m², although permeabilitiesas low as 10⁻¹⁶ m² may be used in certain instances. These results areconsistent with ranges defined by the MGS using a compilation of currentcarbon dioxide storage studies worldwide and are also within the rangesthat might be found in the MRS.

Example 2

In this example, a model of various CO₂-based geothermal systems in anaturally porous, permeable aquifer, i.e., the novel CO₂ PlumeGeothermal (CPG) system is compared to a conventional CO₂-basedengineered EGS and a conventional water-based (i.e., non-EGS) geothermalsystem.

For all sample models, the geometry as shown in map view in FIG. 9 isutilized. The system is (horizontally) one kilometer square and 305 mthick with one injection well at the center and four production wells,one at each corner of the square, as shown in FIG. 9. By symmetry, only⅛^(th) of the system need be modeled, as shown in the gridded area ofFIG. 9. This geometry is typical of early-stage geothermal system modelsand approximates real-world, water-based geothermal installations. Themodel thus provides a direct comparison to water-based geothermal powergeneration systems as well as CO₂-based EGS systems.

Parameters for Sample Models

Unless otherwise noted, the following parameters are used in the modelsof CPG formations that provide the results shown in the figures.

Table 2 shows details of the modeled geothermal reservoir.

TABLE 2 Geothermal Reservoir Specifics Geothermal reservoir Thickness305 meters Distance between injection and production 707.1 meters wellsPermeability 10⁻¹⁴ m² Porosity 20% (i.e., 0.20) Rock grain density 2600kg/m³ Rock specific heat 1000 J/kg/° C. Rock thermal conductivity 2.51W/m/° C. System initial and boundary conditions Reservoir fluid All CO₂or all water Temperature 100° C. Pressure 250 bar Top and sideboundaries No fluid or heat flow Bottom boundary No fluid flow, heatconduction Injection and production conditions Reservoir area 1 km²Temperature of injected fluid 20° C. Injection/production rate 300 kg/sDown hole injection pressure 250 bar Down hole production pressure 240bar Injection/production duration 30 years

CPG System Compared to CO₂-Based EGS System.

FIG. 10 is a graph showing temperature versus distance from theinjection well to a production well for various fracture spacings in theEGS cases (the CPG system does not contain specific fractures but rathera granular porous medium). Specifically, FIG. 10 compares the novel CPGsystem (top line) with several conventional CO₂-based EGS systems usingvarious average fracture spacings (200 m, 100 m and 50 m, from bottom tosecond from the top), thus providing a cross section through the modelgeometry from injection well to production well. As such, FIG. 10displays a temperature “snapshot” after 10 years of injection andproduction in this very low temperature geothermal environment. (The lowtemperature scenario was simulated to illustrate performance at commonlyunfavorable low-temperature conditions. System performance increases forhigher temperatures).

Surprisingly, there are substantial differences between the CPG and EGSmodels. With respect to the CPG case, near pre-production temperatures(and in general higher temperatures) were maintained at the productionwell for much longer than in the EGS models. These results indicatedthere was a more thorough thermal energy recovery in CPG systems ascompared to the conventional EGS models. Hence, it is expected that, inuse, a CPG system will achieve higher efficiency and maintain economicviability longer (due to longer-term production of high-temperaturefluids) than a conventional EGS.

Additionally, after ten (10) years of injection and production, themaximum temperature in the reservoir in the CPG system occurred at theproduction well, which was not the case for the EGS system. Aselectrical energy production efficiency (and viability of systemimplementation) is directly related to fluid temperature, the CPGsystems provided higher efficiency than EGS.

Finally, as the EGS cases revealed, the wider the average fracturespacing, the lower the temperature of produced fluid with time. Thus,all else being equal, CPG systems can be implemented in lowertemperature formations (therefore, in more areas worldwide) than (evenCO₂-based) EGS (let alone water-based EGS). The substantial differencesin produced fluid temperatures between CPG systems and CO₂-based EGSwere surprising and unexpected.

FIG. 11 shows a CPG system in comparison with several CO₂-based EGSexamples, showing heat energy production as a function of time. In theseexamples, for a given pressure differential between injection andproduction wells, the CPG system produced over 1.75 times more heatenergy than a comparable CO₂-based EGS. To produce comparable amounts ofheat energy, EGS required a much higher (more than factor of two)pressure difference between the injection well and the production well.Thus, the EGS had a much greater pumping energy requirement and lowerpower production efficiency than the CPG systems.

CPG System Compared to Water-Based Non-EGS Geothermal System

FIG. 12 compares thermal energy extraction rates between a CPG systemand a water-based regular (i.e., non-EGS, meaning a reservoir/non-hydrofractured) geothermal system, everything else being equal. Surprisingly,thermal energy extraction rates are 1.7 to 2.7 times larger with CO₂than water, which appears to be primarily a result of CO₂ mass flowrates being up to 5 times greater than those of water, given a fixedpressure difference between injection and production wells.Interestingly, based on conventional wisdom, it was expected that CO₂energy extraction rates would be up to 1.5 times larger than those ofwater. See, for example, Pruess, “Enhanced geothermal systems (EGS)using CO ₂ as working fluid—a novel approach for generating renewableenergy with simultaneous sequestration of carbon,” Geothermics 35 (4),pp. 351-367, 2006. Therefore, the above result is surprising in thatconventional practices predict different results, thus teaching awayfrom such a system. Additionally, these results show the widespreadpotential for CPG implementation in areas previously inaccessible togeothermal energy extraction by traditional, water-based means.

CO₂ mass flow rates can be largely attributed to high CO₂ mobility(density to dynamic viscosity ratio, ρ/μ). To note, real-worldgeothermal installations typically operate on a fixed differentialproduction pressure, as has been included in the above models.

FIG. 13 provides density profiles from injection well to productionwell, comparing CO₂ and H₂O cases for two different reservoir depths.These plots are applicable to both naturally porous, permeable (CPG)systems and to EGS. Use of CO₂-based systems (lower two lines indicatingdifferent reservoir depths) compared to water-based systems (upper twocurves indicating different reservoir depths) allows for a large densitychange in CO₂ between injection and production points. A drop in densityfrom injection to production wells drives fluid flow through thesubsurface system, an effect known as a thermosyphon, which reducespumping requirements, a substantial energy draw in geothermal systems.Hence, the CO₂ system has much lower pumping energy requirements than acomparable water-based system.

As a result of these findings, scenarios may be envisioned where a CPGsystem does not even require a pump. Additionally, and surprisingly, thetwo CO₂ curves in FIG. 14 reveal that the injection to productiondensity difference is much larger for CO₂ at shallower depths, while thewater curves reveal little change with depth. This result applies toboth EGS and CPG systems. Therefore, as EGS (with CO₂ or water)typically target much deeper reservoirs than are proposed for CPGsystems, CPG demonstrates increased thermosyphon properties as comparedwith EGS.

Dimensionless numbers can be utilized to further describe the propertiesof CO₂ as compared to water in naturally porous, permeable (i.e.,non-EGS) geothermal systems. For example, the above plot reveals thatthe CO₂ Rayleigh number is much higher than that of water, indicatingCO₂ more readily advects/convects (circulates due to heat energyrecovery) through the reservoir than water (all else being equal).

As the water Prandtl dimensionless number indicates in FIG. 15, ascompared to the Prandtl number for CO₂, water more readily diffusesmomentum than heat. Hence, CO₂ more easily moves through a geothermalreservoir than water, and the increased mobility of CO₂ (see alsostatement about mobility of CO₂ above) ultimately leads to the improvedheat energy recovery of CO₂-based compared to water-based systems.

Surprisingly, the CPG system is able to increase power productionefficiency by utilizing CO₂'s low freezing point. Since CO₂ does notfreeze at 0° C., unlike water, a CO₂ power cycle can use sub 0° C.condensing temperatures in its power system, increasing power productionefficiency on top of efficiency improvements acquired in the geothermalreservoir.

Exemplary Reservoir Parameter Ranges

As a result of the above modeling, various exemplary reservoirparameters were determined as useful in the embodiments describedherein. Of course, other parameters are also possible, which can bedetermined with additional modeling, proto-type testing and full-scaletesting, including the testing described below in Prophetic Example 3.

TABLE 3 Exemplary Reservoir Parameters Permeability 0.5 × 10⁻¹⁵-1 ×10⁻¹¹ m² Porosity 0.05-0.4 Depth below surface 800-5000 m Temperature70-300° C.

Example 3 Prophetic Modeling of CO₂ Reservoir Formation

Modeling of the formation of a CO₂ plume in a geologic structure will beperformed. It is expected that numerical models of CO₂ injection into abrine or hydrocarbon filled geologic formation will show that a large(on the order of a kilometer in area and several tens to hundreds ofmeters thick), near-pure CO₂ plume can be established via displacementof the native fluid. The time period from onset of injection to CO2recovery at production wells is expected to be on the order of severalmonths to two years (maximum 3 years), depending on sitecharacteristics.

It is expected that initial plume formation will require a sequence ofinjection rates and durations designed to ensure thorough displacementof the native reservoir fluid and avoidance of so-called fingering orshort-circuiting effects. It is expected that about 50% to about 95%,such as about 65% to 75%, such as approximately 70% of the injected CO₂will be recoverable at production wells and cycled through the surfacepower system. The remaining fraction of injected CO₂ will be permanentlygeologically sequestered, as this term is understood in the art.

Reactive Transport and Poroelastic Modeling

In addition to physical experiments, modeling of the chemical reactionsamong injected CO₂, native reservoir brine or hydrocarbons, andreservoir rock is useful for understanding the function and the rangesof viable parameters for CPG systems. Similarly, modeling of thephysical responses of a natural aquifer, including pore and matrixdeformation and pressure propagation will be performed.

One geochemical consequence of CO₂ injection into a naturally porous,permeable geologic formation overlain by a caprock (likely shale) thatwe expect to see from our modeling is fluid heating from exothermicreactions. Unique to some CPG systems, and something that is notpossible in water-based geothermal systems and likely not possible inEGS (even CO₂-based EGS which would typically not include a caprock),are CO₂ reactions with some caprock minerals that produce heat. Becausecomparable water reactions are rare in geologic reservoir environmentsand EGS likely will not encounter native rocks that allow suchreactions, CPG systems are uniquely able to make use of such geochemicalbehavior to enhance heat energy recovery. CO₂ injected into a geologicformation will naturally rise to the top of the formation, where it willrest against/underneath the local caprock. Should exothermic reactionsoccur, they would impart heat to the CO₂, which could be recovered toproduce electricity as the fluid cycles through the CPG system. At thesame time, these CO₂-mineral reactions can be volume-increasing therebyserving to (further) seal the caprock. Such reactions may not occur inthe reservoir itself if the reservoir rocks/minerals/sediments are of adifferent composition than the caprock materials.

Coupled Reservoir-Wellbore Modeling

Modeling fluid flow from the geologic reservoir through the wellbores isuseful for the calculation of pumping requirements and permitsestimation of fluid heating or cooling in the wells. It is expectedthat, because of the (greater) depths and temperatures typicallytargeted for EGS compared to those used for CPG systems, CPG systemswill result in less CO₂ cooling than CO₂-based EGS as the heated fluidmoves from the reservoir to the surface, showing further energy recoveryimprovements of CPG as compared to EGS.

Layered Reservoirs

Future models will account for fluid movement through the verticaldimension of a geologic formation, whereas models to date assumeprimarily lateral flow. It is expected that accounting for the thirddimension (i.e., vertical dimension) will reveal additional features,such as improved heat recovery in CPG systems, as compared withCO₂-based EGS (and water-based EGS and non-EGS systems) because in theCPG system, the heat transfer fluid will encounter considerably moreheated rock.

Geochemical Reaction Experiments

Other experiments will examine geochemical reactions among CO₂, brine orhydrocarbons, and rock under temperature, pressure, and compositionconditions that would be encountered in CPG systems or CO₂-based EGS. Itis expected that the sedimentary rock reservoirs that would very oftenbe used for CPG systems (because of depth, porosity, permeability, andexistence of traps (reservoir with overlaying caprock that may alsoinclude a low permeability feature such as fault in some instances)),among other reasons, will show lower reactivity than the reservoirstypically accessible for EGS (because of the greater depths targeted forEGS). As such, EGS reservoirs are expected to be more easily clogged bymineral precipitation or short-circuited due to mineral/rock/sedimentdissolution reactions which both can render such systems unusable.

CONCLUSION

The carbon dioxide-based energy generating system described hereinprovides a novel means for producing renewable energy, while furtherproviding for carbon dioxide sequestration, thus providing a processwith a negative carbon footprint. In one embodiment the geothermal powerplant has a negative carbon dioxide output, thus providing the firstelectricity-generating power scheme with a negative carbon footprint.Carbon dioxide sequestration also provides added revenue to a powerplant under a carbon-trading market. In contrast to conventional EGS(conventional water-based EGS and conventional CO2-based EGS) siteswhich utilize large-scale hydrofracturing of rocks to create a usablereservoir, the embodiments described herein rely on natural orpreviously created reservoirs (including previously fractured naturalgas formations) in combination with only minor disturbances at most,such that the target formation remains in situ, thus minimizing thenegative effects of large-scale hydrofracturing described herein andknown in the art. In one embodiment, a global warming reduction systemis provided.

In embodiments which utilize supercritical carbon dioxide, the excellentthermodynamic, fluid dynamic, and chemical properties of this workingfluid provide new ways of generating electric power in regions formerlyunimaginable for this purpose, such as the eastern and mid-western partsof North American may now be considered for renewable, clean, geothermalelectricity production. This approach further enhances the efficiency ofgeothermal power plants, particularly during colder months, as comparedto traditional water-based systems, thereby potentially allowingelectricity production in such low heat flow regions, such as, forexample, Minnesota, and other climatologically and geologically similarlocations in a sustainable and highly efficient manner. Such plants arealso expected to be more compact than water-based versions, therebyreducing the plant's spatial and environmental footprint.

Compared to water, carbon dioxide can be cooled well below zero (0)° C.(above atmospheric pressure), such as about −55° C., without freezing.Carbon dioxide additionally allows the whole system to be run underpressures higher than ambient pressures. In contrast, water systemsapply partial vacuums in parts of the cycle, which are prone to leaks.Additionally, the increased pressure allows for higher fluid densities,as compared to water, and thus smaller piping and other componentsreducing capital investment costs.

In one embodiment, the system is a closed loop carbon dioxide systemwithout a carbon dioxide sequestration component. In other embodiments,the ability to contain carbon dioxide with use of an open loop orpartially open loop system further enhances the efficiency of the systemand provides a means to sequester carbon dioxide from, for example, aconventional power plant. In fact, by not recovering all of the carbondioxide, some or most of the carbon dioxide (e.g., from about five (5) %to about 95%, can be sequestered. Additionally, these same systems andmethods can also be applied to providing geothermal energy to heat pumpsfor space heating or for direct use, as described herein. In contrast towind and solar power systems, geothermal systems are highly scalable andcan provide base-load and dispatchable (peak) power as desired.Similarly, on a human-time scale, geothermal energy is a renewableenergy resource and it is cheaper than coal, wind, nuclear, etc. andcomparable in cost to natural gas.

The carbon dioxide-based geothermal energy generating system can be usedto produce energy for a number of uses, including for commercial sale,process load (to operate the geothermal power or CO2 sequestrationsystem) and electricity generation. In the exemplary embodimentsdescribed in detail herein, the system is designed to generate energy inquantities sufficient to provide electricity, to provide heat for on- oroff-site uses, to provide shaft power to operate the on-site equipment,or combinations thereof, and the like. In this way, the use of fossilfuels, such as natural gas, is limited, while operational costs arereduced.

Embodiments of the novel system and methods described herein provide,for the first time, the ability to provide electricity from a geothermalsource at temperatures much lower than are required for conventionalwater-based geothermal systems, although higher operating temperaturesmay optionally be used.

Embodiments of the novel systems and methods described herein areefficient, economical and relatively simple in operation. In oneembodiment, the process uses a production waste product (CO₂) that mustotherwise be properly disposed of, sometimes at significant costs.Various embodiments also allow an operating liability to be turned intoa business asset, while simultaneously providing environmental benefits.

Embodiments of the invention can be employed as part of a simplifiedcost-effective geothermal energy system using natural state rockformations as subterranean in situ rock reservoirs. Various embodimentscan also be used for subterranean carbon sequestration and permanentstorage of CO₂. The use of saline aquifers and saline water-filled rockformations in one embodiment further allows water to be utilized whichis unlikely to be used for consumption or irrigation. Embodiments mayfurther be part of an enhanced oil recovery (EOR) scheme and otherhydrocarbon extraction methods, thereby enhancing hydrocarbon recovery(in addition to providing geothermal energy and to providing a means tosequester CO₂).

In one embodiment, the source of the carbon dioxide and carbondioxide-based geothermal energy generating system are located on thesame site or less than about one (1) km of each other, although theinvention is not so limited. In one embodiment, the energy generationsystem is in close proximity to the carbon-dioxide producing source,such that energy which is generated with the system described herein isconsumed partially or completely as power to the facility itself, thuseliminating the need for an elaborate and expensive piping system. Inother embodiments, the energy produced with the energy generating systemis piped any desired distance to be utilized in any desired manner. Inyet other embodiments, some or all of the energy is used to power othertypes of manufacturing facilities and/or is sold to a local utility,and/or is used to generate electricity on-site.

Although specific embodiments have been illustrated and describedherein, it will be appreciated by those of ordinary skill in the artthat any arrangement that is calculated to achieve the same purpose maybe substituted for the specific embodiments shown. For example, althoughthe embodiments have been described with carbon dioxide as the workingfluid, in other embodiments, fluids other than carbon dioxide, havingthe properties, may be used. Additionally, a working fluid may beinjected as part of an enhanced oil recovery (EOR) or enhanced naturalgas or other hydrocarbon recovery scheme. This application is intendedto cover any adaptations or variations of the invention. It is intendedthat this invention be limited only by the following claims, and thefull scope of equivalents thereof.

1. A system comprising: one or more injection wells for accessing anunderground reservoir having a first temperature, wherein the reservoiris located below one or more caprocks, wherein the reservoir isaccessible without using large-scale hydrofracturing, each of the one ormore injection wells having an injection well reservoir opening in fluidcommunication with the reservoir; one or more production wells, eachhaving a production well reservoir opening in fluid communication withthe reservoir; a working-fluid supply system for providing a non-waterbased working fluid to the one or more injection wells at a secondtemperature lower than the first temperature, wherein exposure of thenon-water based working fluid to the first temperature produces heatednon-water based working fluid capable of entering each of the one ormore production well reservoir openings; and an energy convertingapparatus connected to the one or more productions wells, whereinthermal energy contained in the heated non-water based working fluid isconverted to electricity, heat, or combinations thereof, in the energyconverting apparatus.
 2. The system of claim 1, wherein each of the oneor more injection wells and each of the one or more production wells arelocated in a common channel and the system further comprises one or moreinjection pipes and one or more production pipes connected to the commonchannel.
 3. The system of claim 1, further comprising a non-water basedworking fluid source.
 4. The system of claim 1, wherein the non-waterbased working fluid is carbon dioxide.
 5. The system of claim 4, whereinthe carbon dioxide is obtained from a power plant or an industrialplant.
 6. The system of claim 4, wherein the carbon dioxide issupercritical carbon dioxide,
 7. The system of claim 1, wherein theenergy converting apparatus comprises at least one of: one or moreexpansion devices, one or more generators, and one or more heatexchangers.
 8. The system of claim 7, wherein the one or more expansiondevices and the one or more generators provide electricity to anelectricity provider.
 9. The system of claim 7, wherein each of the oneor more heat exchangers provide heat to a heat provider.
 10. The systemof claim 1, further comprising one or more cooling units in fluidcommunication with the one or more production wells and the one or moreinjection wells.
 11. A method comprising: without using large-scalehydrofracturing, accessing an underground reservoir having a naturaltemperature, the reservoir being located beneath one or more caprocks;introducing a non-water based working fluid into the one or morereservoirs through one or more injection wells; exposing the non-waterbased fluid to the natural temperature to produce heated fluid;producing the heated fluid through one or more production wells; andextracting thermal energy from the produced heated fluid.
 12. The methodof claim 11, wherein the non-water based working fluid is carbondioxide.
 13. The method of claim 12, wherein the carbon dioxide issupercritical carbon dioxide.
 14. The method of claim 11, wherein theheated fluid also contains native fluid present in the one or morereservoirs.
 15. The method of claim 11, wherein the one or morereservoirs each have a porosity ranging from about one (1) % to about50% and a permeability ranging from about 10⁻¹⁶ m² to about 10⁻⁶ m². 16.The method of claim 11, wherein the natural temperature is between about−30° C. and about 300° C.
 17. The method of claim 11, wherein thethermal energy is used for at least one of: producing electricity;heating a working fluid in one or more heat exchangers; providingcondensed fluid to the one or more reservoirs; providing cooled fluid tothe one or more reservoirs; or providing shaft power to one or morepumps or compressors.
 18. The method of claim 17, wherein theelectricity is produced either by providing the hot fluid to one or moreexpansion devices or by providing the working fluid heated in the one ormore heat exchangers to the one or more expansion devices, wherein theone or more expansion devices produces shaft power to one or moregenerators, which, in turn, produce the electricity.
 19. The method ofclaim 17, wherein the working fluid heated in the one or more heatexchangers provides heat for at least one of: direct use; forgroundwater heat pumps; or for a Rankine power cycle.
 20. The method ofclaim 11, further comprising: choosing the underground reservoir;transporting a non-water based working fluid source to an area proximateto the injection well; converting the non-water based working fluidsource into the non-water based working fluid; and providing the heatenergy to a customer.